Processes and systems for characterizing and optimizing fracturing fluids

ABSTRACT

A workflow to optimize a fracturing fluid for injection into a subterranean formation is provided. The workflow comprises measurement of fundamental properties and characteristics of reservoir rock and fluid, their interaction with fracturing fluid, computer-based models and laboratory performance testing to select preferred fracturing base fluid and additives package for use in fracturing/re-fracturing stimulation of specific shale formations to enhance hydrocarbon recovery.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application claims priority and benefit as a continuationpatent application from U.S. application Ser. No. 15/222,716, filed onJul. 28, 2016, which is incorporated by reference in its entirety. Thisapplication claims benefit under 35 USC 119 of U.S. Provisional PatentApp. No. 62/197894 with a filing date of Jul. 28, 2015, which isincorporated herein by reference in its entirety and for all purposes.

TECHNICAL FIELD

The invention relates generally to systems and methods forcharacterizing and optimizing fluids for use in fracturing asubterranean formation to improve production and hydrocarbon recovery.

BACKGROUND

Unconventional development of oil and gas shale and tight reservoirs hasglobally become very active in the past ten years due to advances inhydraulic fracturing operations. Due to the tightness of the shale rockformations (generally much less than 1-md and often measured innano-darcy), hydraulic fracturing enables enhanced production byproviding more contacts with the reservoir and allow ease of fluidproduction into the wellbore.

Hydraulic fracturing generally entails injecting a fluid into thewellbore at a sufficient rate and pressure to part or open existingfractures and/or overcome the tensile strength of the formation and, inthe case of shallow, horizontal fractures, the formation overburdenpressure. The injected fluid (“fracturing fluid”) creates cracks orfractures extending from the wellbore out into the formation, which maybe often propped open with a proppant entrained in the fluid. Thefractures permit hydrocarbons and other fluids to flow more freely intoor out of the wellbore.

It is desirable to optimize the physical and chemical properties of afracturing fluid. A fracturing fluid should be compatible with thereservoir rock and reservoir fluids, have sufficient viscosity andstructure to suspend proppants if present, and transport them deep intothe formation, be stable enough so as to retain sufficient viscosity andstructure throughout proppant placement, possess low fluid lossesproperties, be easily removed from the formation, present low fluid flowfriction pressures, be easily made under field conditions, be relativelyinexpensive, and exhibit high levels of rheological performance.

Each shale play and reservoir inherently contains different rock andfluid types of varying properties. The reservoir interaction to aspecific fracturing fluid can vary significantly and result in differentproduction outcomes. In the prior art, different fracturing fluidcompositions are tested for a particular reservoir until one chemistry(composition) is found that provides fracture effectiveness foroperation and cost. The trial-and-error process can consume significanttime and cost until a fluid is found for a particular reservoir.

Different types of fracturing fluids have been tried in the prior art.Dispersing fracture fluids are those which include aqueous solutions ofmonovalent cation salts, including organic sulfates, phosphates,chlorides, fluorides, citrates, acetates, tartrates, hydrogen phosphatesor a mixture thereof. A dispersing fracture solution in the fracturezone will disperse clays and other earthen particles and allow them tobe carried by the flow-back fluids out of the hydrocarbon producingfracture zone. This process increases hydrocarbon production when thepay zone does not contain a lot of clay. Aggregating fracture fluids arethose which include aqueous solutions of di- and trivalent cation salts,e.g., calcium chloride (CaCl₂), iron chloride (FeCl₃), magnesiumchloride (MgCl₂), di- and trivalent metal salts of carboxylic acids. Anaggregating fracture solution will aggregate and bind clays and otherearthen materials. This stabilizes the fracture zone but will eventuallyclog and occlude the pay zone with the clay particles that are notaggregated by the cation salts. Many fracturing fluid materials whenused in un-optimized concentrations have relatively poor “clean-up”properties, meaning that such fluids undesirably reduce the permeabilityof the formation and proppant pack after fracturing the formation.

There is still a need for improved methods and systems to characterizeand optimize fracturing fluid chemistry. There is also a need forimproved methods and systems to optimize fracturing fluid chemistrytaking into consideration of factors including but not limited toimbibition, diffusion and interrelations between the fracturing fluidand reservoir rock in the fracturing fluid chemistry optimization(FFCO).

SUMMARY OF THE INVENTION

Embodiments of optimizing fracturing fluids are provided herein. Oneembodiment of a method for optimizing fracturing fluid compositions forinjection into a subterranean formation includes providing a pluralityof rock samples being representative of a rock matrix within asubterranean formation containing hydrocarbons for recovery; providing aplurality of brine samples being representative of formation brines ofthe subterranean formation; providing a plurality of hydrocarbon samplesbeing representative of hydrocarbons recoverable from the subterraneanformation; characterizing the rock samples to obtain one or more rockparameters representing geochemistry properties of the rock samples,petrophysical properties of the rock samples, or any combinationthereof; characterizing the brine samples to obtain one or more brineparameters representing alkalinity properties of the brine samples,salinity properties of the brine samples, total dissolved solids (TDS)properties of the brine samples, or any combination thereof;characterizing the hydrocarbon samples to obtain one or more hydrocarbonparameters representing acidity properties of the hydrocarbon samples,polarity properties of the hydrocarbon samples, molecularcharacteristics properties of the hydrocarbon samples, or anycombination thereof; synthesizing at least two fracturing fluid samplesbased on the rock parameters, the brine parameters, the hydrocarbonparameters, or any combination thereof; and conducting a test on atleast one rock sample and the at least two fracturing fluid samples toevaluate rock-fluid interactions. The test comprises an interfacialtension test to determine contact angle, zeta potential, wettability,interfacial tension properties, or any combination thereof; an ionselectivity test to determine ion selectivity properties; a cationexchange capacity test to determine cation exchange capacity properties;a disjoining pressure test to determine disjoining pressure properties;an adsorption desorption simulation test to determine cation exchangeand charge compensation properties; a forced imbibition test to evaluatekinetic and mass transfer properties; or any combination thereof. Themethod further includes preparing at least one fracturing fluid forinjection into the subterranean formation based on at least twocriteria, wherein the criteria comprises the rock parameters, the brineparameters, the hydrocarbon parameters, the contact angle properties,the zeta potential properties, the wettability properties, theinterfacial tension properties, the ion selectivity properties, thecation exchange capacity properties, the disjoining pressure properties,the cation exchange and charge compensation properties, the kinetic andmass transfer properties, or any combination thereof.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates a schematic diagram showing the steps carried out ina method for developing at least one optimized fracturing fluid for ahydraulic fracturing operation, according to one embodiment.

FIGS. 2A-2B illustrate schematic diagrams showing various samples andtests that can be utilized in a method for tailoring a fracturing fluidfor a particular reservoir/rock formation, according to one embodiment.

FIG. 3 illustrates a schematic diagram of a reaction vessel for anenhanced imbibition test, according to one embodiment.

FIG. 4 illustrates NMR T1-T2 measurements before and after treatment,according to one embodiment.

FIG. 5 illustrates electrochemical potential apparatus setup, accordingto one embodiment.

FIG. 6 illustrates a schematic diagram of an imbibition test setup,according to one embodiment.

DETAILED DESCRIPTION

The following terms will be used throughout the specification and willhave the following meanings unless otherwise indicated.

“Hydrocarbons” or “hydrocarbonaceous” or “petroleum” or “crudes” may beused interchangeably to refer to carbonaceous material originating fromsubterranean sources as well as synthetic hydrocarbon products,including organic liquids or gases, kerogen, bitumen, crude oil, naturalgas or from biological processes, that is principally hydrogen andcarbon, with significantly smaller amounts (if any) of heteroatoms suchas nitrogen, oxygen and sulfur, and, in some cases, also containingsmall amounts of metals. Crude oil (e.g., liquid petroleum) and naturalgas (e.g., gaseous petroleum) are both hydrocarbons.

“Hydraulic fractures” are fractures or cracks which are introduced intoa subterranean formation by injecting a fluid into the formation at apressure greater than the parting or fracture pressure of the formation.Hydraulic fractures can have a substantially vertical orientation atdepths greater than about 350 meters, and the parting or fracturepressure is the pressure at which open fractures are created, either byopening existing closed fractures or exceeding the rock tensile stress.Fractures can also be substantially horizontal, and the parting pressuremay be the overburden pressure or the sum of the overburden pressure andthe tensile stress of the formation.

“Well” and “wellbore” are used interchangeably to denote a boreholeextending from the earth surface to a subterranean formation and atleast partially in fluid communication with a subterranean formation.

A “production wellbore” enables the removal of fluids from the formationto the surface and an “injection wellbore” enables the placement offluid into the formation from the surface. In hydraulic fracturing, theproduction wellbore may temporarily have an injection function or usedas an injection wellbore for placement of the fracturing fluid in theformation.

“Fluid” is inclusive of a gas, a liquid, and/or mixtures thereof.

“Fracturing fluid” or “frac fluid” refers to the fluid that is pumpedinto the well to create conductive fractures. The fracturing fluid canbe any of water-based fluids, viscosified water-based fluids,non-viscosified water-based fluids, gelled oil-based fluids, acid-basedfluids, foam fluids, and mixtures thereof.

“Formation brine” or “formation water” refers to water that occursnaturally within the pores of the inorganic matrix of the subterraneanformation. “Connate brine” or “connate water” refers to water that istrapped in the pores of a rock during its formation.

“Imbibition” refers to a process of absorbing a wetting phase, e.g., afluid, into a rock and in one embodiment, displacing another fluid inthe process. “Spontaneous imbibition” refers to the process ofabsorption with no pressure driving the phase into the rock. It ispossible for the same rock to imbibe both water and oil, with waterimbibing and displacing excess oil from the surface of the rock grains.It is also possible for oil to imbibe, displacing excess water from thesurface of the rock grains.

“Wettability” refers to the preference of a solid, e.g., a rock, tocontact one liquid or gas, e.g., a fluid or a wetting phase, ratheranother fluid. The wetting phase will tend to spread on the solidsurface and the solid will tend to imbibe the wetting phase and displacea non-wetting phase. There is a correlation between the wettabilityproperty of a rock and its properties such as relative permeability,electrical properties, nuclear magnetic resonance relaxation time, andsaturation profiles in the reservoir. A rock can be water wet, oil wet,or intermediate wet. In one embodiment, wettability is indicated ormeasured by using the Amott test, which combines two spontaneousimbibition measurements and two forced displacement measurements,defining two different indices: the Amott water index I_(w) and theAmott oil index I_(o). The indices are combined to give the Amott-Harveyindex (AI=I_(w)−I_(o)), which results in a number between +1 (stronglywater-wetting) and −1 (strongly oil-wetting).

“Intermediate wet” refers to a state that can be mixed-wet, in whichsome surfaces or grains are water wet and some are oil-wet, or aneutral-wet, in which the surfaces or grains are not strongly wet byeither oil or water.

“Zeta potential” is a parameter characterizing electrochemicalequilibrium on interfaces, wherein the zeta potential depends on theproperties of liquid as well as on properties of the surface. Zetapotential may be calculated from electrophoretic mobility measurementsin which an electrical current is passed via electrodes through anaqueous suspension consisting essentially of formation mineral colloidalparticles, and determining the direction and speed of the colloidalmovement.

“Salt” refers to a composition of at least one cation and at least oneanion that forms ions in aqueous solution. The ions may include suchcations as sodium, potassium, calcium, barium, magnesium, ammonium,tetraalkylammonium, and the like. The salts may also include such anionsas chloride, bromide, iodide, carbonate, bicarbonate, sulfate,bisulfate, borate, phosphate, nitrate, silicate, acetate and citrate,and the like. Compositions containing salts may be referred to as“salinities.”

“Interfacial tension” or “IFT” refer to the surface tension betweenvarious rock-fluid interfaces (e.g., oil and water) due to differentsalinities and different concentrations.

“Cloud point” refers to a temperature point at which a compound becomesinsoluble in an aqueous solution, the temperature at which the compoundbecomes hydrophobic enough to separate from the aqueous solution,becoming a colloidal suspension or macro-emulsion.

“Water-sensitive minerals” refers to minerals that when contacted byaqueous fluids in disequilibrium with the minerals in the formation, theminerals tend to swell and/or migrate.

In hydraulic fracturing, hydrocarbon is recovered from a formation whererock is fractured by a pressurized liquid. Hydraulic fracturing involvesthe high pressure injection of a fracturing (fracking) fluid into awellbore. The fracturing fluid is primarily water with sand and/or otherproppants, injected into the wellbore to create cracks through whichhydrocarbons (e.g., gas and/or crudes) and formation brines can flow.When the hydraulic pressure is ceased to apply to the well, theproppants hold the fractures open for the recovery of hydrocarbons (andformation brine) from the same wellbore.

Contact between any fracturing fluid with the surface of minerals isaccompanied by adsorption. There are two types of adsorption: physicaland chemical. One distinction between physical and chemical adsorptionis in the differences of the forces that hold adsorbed molecules on asolid surface. Forces of electrostatic origin such as the Van deer Waalsforces are responsible for the physical adsorption. If acting forces areof chemical nature (e.g., exchanges forces), then such adsorption iscalled chemical.

It is believed that with the selection/design of the right chemistry forthe fracturing fluid composition, fracture effectiveness as well aslong-term well performance can be enhanced. This invention relates toimproved methods and systems, overcoming the trial-and-error approach ofthe prior art, to optimize the design and selection of fracturing fluidfor use in hydraulic fracturing. The systemic approach includescomprehensive data collection and analysis to capture the keyinfluencing physics and predictive methods, both statistical andmechanistic modeling, to enable the selection of optimal fracturingfluids designed for tight rock formations or shale plays.

In one embodiment, the method relates to systematic assessment ofrock-fluid interactions to evaluate, design, and select fracturingfluid(s) applicable to specific rocks or reservoirs. The systematicassessment is suitably for any type of rock formation, including tightgas, oil, shale, carbonate, coal reservoirs, e.g., including shale rockwith very low permeability much less than 1-md such as 0.00001 md, andmeasured in nano-darcy. The systematic assessment takes into account thephysical and chemical adsorption characteristics of the fracturingfluid, i.e., brine water and organic compounds and molecules on rock andmineral surfaces and within their aggregate pore systems, includingmolecular interactions via charge compensation and other mechanismsbetween the hydrocarbon molecules and mineral and organic surfaces atthe atomic level. The assessment also takes into account imbibition asone of the determining parameters, specifically spontaneous imbibition,which is the imbibition by action of capillary pressure when a coresample is surrounded by a fracturing fluid/brine. FIG. 1 is a schematicdiagram showing the steps carried out in a systematic method fordeveloping a fracturing fluid for a hydraulic fracturing operation,according to one embodiment.

In order to optimize fracture fluids for maximum production, it isnecessary to have an objective understanding and comparison betweencandidates related to the rock properties controlling fluid transportand phase wettability. Following fundamental characterization of theoil, rock and formation water in a field of interest, aliquot sampleswill be treated with potential fluid compositions not limited to aspecific number (FIGS. 2A-2B). For each rock test candidate,characterization includes a number of key tests or measurements torepresent the rock characteristics.

Rock Samples: One of the steps in the method is obtaining a library ofrock samples in different forms and from different reservoirs, includingbut not limited to samples of mineral standards and core plugs. The rocksamples can be shale materials, e.g., laminar shales, dolomitic shales,limy shales, etc., and combinations thereof. Mineral standards mayinclude sandstone, clay, non-clay minerals, quartz and calcite. The rocksamples can be obtained from wellbores, e.g., core samples fromexploratory wells, production wells, wells being drilled or have beendrilled. The rock samples can also be from cuttings present in thereturns of a well being drilled. The rock samples can be “artificial”core samples, e.g., mixture of rocks from various locations. The rocksamples can be any of powdered form, individual or composite samplesfrom rock formations, discs, core plugs, crushed materials, suitable fortests to obtain representative characteristics of the reservoirs.

In one embodiment, the library includes at least one mineral that has anegative zeta potential (i.e., a negative surface electric charge) underreservoir condition. In another embodiment, the library includes avariety of minerals from various rock formations, e.g., smectite lowcharge, smectite high charge, illite, quartz, calcite, mixed-layeredillite-smectite, and kaolinite. In yet another embodiment, the libraryincludes samples of water-sensitive mineral or several species, e.g.,silica; iron minerals; alkaline earth metal carbonates, feldspars,biotite, illite, and chlorite; smectite clays such as montmorillonite,beidellite, nontronite, saponite hectorite and sauconite; kaolin clayssuch as kaolinite, nacrite, dickite, endellite and halloysite; illiteclays such as hydrobiotite, glauconite and illite; chlorite clays suchas chlorite, greenalite and chamosite; other clay minerals not belongingto the above groups such as vermiculite, palygorskite, sepiolite;mixed-layer (both regular and irregular) varieties of the aboveminerals; and any combination thereof.

In one embodiment, the library includes a number of artificial coresamples, e.g., mixtures of quartz, silica, etc., compacted in a specificdemountable forms and burnt gradually at different temperatures, e.g.,300° C., 500° C., 800° C., etc., simulating rock samples in certainformations/reservoirs.

Hydrocarbon Samples for Rock-Fluid Interaction Assessment: In oneembodiment, samples of crudes from reservoirs in the library are alsoassembled for the systematic assessment. The crudes of differentcharacteristics can provide an array of interactions with the fracturingfluids based on their polarity (e.g., polar and non-polar), acidity(e.g., highly acidic, highly basic), and differences in molecularcontent. In one embodiment, the collection includes crudes withsignificant polar organic molecules and high asphaltene (C10+) contents,crudes with a non-polar characteristic and relatively high asphaltene,and crudes as well as condensate with a higher proportion of lightermolecules (<C10).

In one embodiment, the hydrocarbon samples also include modeland/synthetic compounds, e.g., decane, mineral oil. In anotherembodiment, model hydrocarbon compounds representative of certain crudeoil classes, e.g., aliphatic, aromatic, resins, asphaltenes, etc., areprovided for testing to monitor adsorption/desorption processes as aresult of cation exchange processes and related changes in wettability.

Brine: In one embodiment, brine or water samples produced from the sameor nearby formations of the reservoirs (for the rock samples) may begathered for analyses, particularly when the brine may be used as thewater source for the fracturing fluid. Such formation water may containamounts (concentration) of precursor ions, such as divalent sulfate(SO⁴⁻) which may form insoluble salts when they come into contact withcations, such as Ba⁺⁺, Sr⁺⁺, and Ca⁺⁺ resident in the formation. Thewater may be injected into the formation by itself (unprocessed asproduced water) as a component of the fracturing fluid, or it can betreated using a strainer, and/or multimedia filters, and/or a membranebased system.

Water for Fracturing Fluid: Water for use in “designing” the fracturingfluids may be from any source, provided that it does not containcomponents that might adversely affect the stability and/or performanceof the first treatment fluids or second treatment fluids of the presentinvention. The water can be from a fresh water source, or include brines(formation and/or synthetic brines). Examples of suitable brines mayinclude, but are not necessarily limited to, heavy brines, monovalentbrines, divalent brines, and trivalent brines that comprise solublesalts like sodium chloride, calcium chloride, calcium bromide, zincbromide, potassium carbonate, sodium formate, potassium formate, cesiumformate, sodium acetate, potassium acetate, calcium acetate, ammoniumacetate, ammonium chloride, ammonium bromide, sodium nitrate, potassiumnitrate, ammonium nitrate, ammonium sulfate, calcium nitrate, sodiumcarbonate, potassium carbonate, any combination thereof, and anyderivative thereof.

In one embodiment, the fracturing fluid is a mix of fresh water andbrine with optional addition of monovalent/multivalent cations. Aplurality of synthetic brine samples may be provided for the systematicassessment, e.g., brine samples at different concentrations of 0.02,0.25, 0.50, 1, 2 and 5N (N, normality in volume per liter) with varioussalts including but not limited to NaCl, KCl, CaCl₂, MgCl₂, AlCl₂, NH₄Cland mixtures thereof.

In one embodiment with the use of formation brine, the formation brinemay be first treated with the removal of some monovalent and/ormultivalent cations, e.g., removal of about 60-90% of the cationspresent, along with the associated anions such as chloride, fluoride,and bromide. In another embodiment, after the removal of some ofcations, some other cations can be added (e.g., monovalent and/ormultivalent cations) to the brine water.

Additives For Use in Fracturing Fluid: In one embodiment instead of orin addition to the various salts to make up a fracturing fluid, variousadditive chemicals are added for the fracture treatment. In oneembodiment, low concentrations (<2 wt. %) of between 3 and 12 additivechemicals are added to each fracturing fluid sample. The selection andamount added depends on the characteristics of the water and theformation being fractured. Examples may include but are not limited tofluid loss control additives, nucleophilic agents, biocides, frictionreducers, pH reducing agents, soaps (surfactants), polymers and mixturesthereof.

In one embodiment, some of the fracturing fluids include amounts ofnon-ionic chemical to help release the oil trapped in the pore spaces.In another embodiment, some of the fracturing fluids include surfactantsto help reduce the interface tension (IFT) between the water and the oilallowing the trapped oil to escape from the pore spaces. The surfactantscan also help alter the wettability of the reservoir rock and helpreduce the adsorption of the non-ionic chemicals by the reservoir rock.Examples of non-ionic chemicals include compounds that are soluble inthe fracturing fluid, e.g., having HLB (hydrophilic lipophilic balance)greater than 10, and cloud point (CP) above surface and reservoirtemperature (e.g., between 30 to 150° C.).

In one embodiment, the fracturing fluids for the study include 0.05 to 5vol. % of non-ionic chemicals or surfactants selected from alcoholalkoxylates, alkyl alkoxylated esters and alkyl polyglycosides. Inanother embodiment, at least some of the fracturing fluids furthercomprise amounts of hydrophobically-modified cationic polymers. Inanother embodiment, the fracturing fluids include amounts ofaqueous-miscible fluids, e.g., alcohols, glycerin, glycols, polyglycolamines, polyols, any derivative thereof, or any combination thereof.Examples of suitable alcohols may include, but are not necessarilylimited to, methanol, ethanol, propanol, iso-propanol, butanol,tert-butanol, and the like. Examples of suitable glycols may include,but are not necessarily limited to, polyglycols, propylene glycol,ethylene glycol, and the like.

In some embodiments, the fracturing fluid samples may further include agas, and/or a foaming agent. Suitable gases for use in the fracturingfluid may include, but are not limited to, nitrogen, carbon dioxide,air, methane, helium, argon, and any combination thereof. Suitablefoaming agents include cationic foaming agents, anionic foaming agents,amphoteric foaming agents, nonionic foaming agents, or any combinationthereof.

Compatability: The fracturing fluid evaluation and optimization processmay include fracture fluid compatibility tests to ensure fracture fluidmay not negatively impact the formation rock (mineralogy) and/orformation fluids. Compatability tests include, but are not limited to,fracturing fluid and fluid additive compatibility test of planned sourcewater and planned fracturing fluid system, fracturing fluid and proppantcompatibility test, fracturing fluid and formation fluid compatibility,or any combination thereof. Signs of incompatibility through these testsinclude clouds, precipitates, phase separation, etc. If anyincompatability is determined, the incompatability may be addressedand/or compatible alternatives may be pursued.

As an example, one embodiment includes verifying compatibility ofcomponents in the at least one fracturing fluid before injection intothe subterranean formation. As another example, one embodiment includesverifying compatibility of the at least one fracturing fluid with atleast one other fluid that will also be injected into the subterraenanformation before injection of the at least one fracturing fluid into thesubterranean formation.

The surfactant in a fracturing fluid to be injected may also be checkedfor compatibility. For example, in one embodiment, where the at leastone fracturing fluid for injection into the subterranean formationincludes a surfactant, the embodiment includes verifying thecompatibility of the surfactant with at least one other additive of theat least one fracturing fluid before injection of the at least onefracturing fluid into the subterranean formation. As another example, inone embodiment, where the at least one fracturing fluid for injectioninto the subterranean formation includes a surfactant, the embodimentincludes verifying the compatibility of the surfactant with atemperature condition of the subterranean formation, a salinity of aformation brine of the subterranean formation, hydrocarbons in thesubterranean formation, or any combination thereof before injection ofthe at least one fracturing fluid into the subterranean formation. Forexample, brine samples and hydrocarbon samples that were previouslyobtained may be used for this verification. Alternatively, new brinesamples, new hydrocarbon samples, or both may be obtained for thisverification. The temperature condition may be obtained using at leastone temperature sensor.

Library (Database) with Data Characterizing Rock-Fluid Interactions &Effects: In the following sections, the term brine may be usedinterchangeably with “fracturing fluid” or “fluid,” in reference to thefluid samples being tested to provide data for the library, whether it'sformation brine, synthetic brine, or a “designed” fracturing fluid fortesting with the rock samples from the reservoirs collected for thesystematic assessment.

In one embodiment, a wide variety of tests are carried out with therocks and fluid samples to characterize rock-fluid interactions andtheir combined effects on the recovery of hydrocarbons, e.g., potentialwettability changes due to imbibition process, mass transfer kinetics ofdiffusion, etc. Due to the tight nature of shale formations withextremely low porosity and permeability, molecular interactions occurvery slowly, with measurements over time being collected for the libraryof test results.

The library can grow overtime with additional molecular interactionmeasurements and data for new reservoirs under evaluation. The librarycontains measurements related to molecular material exchanges (e.g.,adsorption/desorption) and hydrocarbon release (e.g., kineticimbibition) from rock-fluid interactions, with experiments withminerals, formation rocks, brines and additives (as fracturing fluids),and crude oils of various compositions and sources, simulating differentformation conditions (e.g., pressure, temperature). The library can alsoinclude data from actual field trials with existing reservoirs andimplemented fracturing fluids. Data from the library facilitates futurefocus experiments for specific interactions of relevant organicmolecules, hydrocarbon fluids, and rock types with fracturing fluids fora new reservoir under study. FIG. 1 is a schematic diagram illustratingvarious samples and tests that can be utilized in building a library foruse to optimize a fracturing fluid for a particular reservoir/rockformation, according to one embodiment.

Preparation of Rock Samples: In some embodiments, reservoir rock samplesare collected from preserved core or core that still containssignificant crude oil saturation. In some embodiments, before theexperiments are conducted to evaluate the interactions of the fracturingfluid for particular reservoirs, e.g., wettability measurements, therock samples are “restored” to mimic the reservoir conditions. In someembodiments, the plugs from the targeted reservoirs are saturated withfluids, e.g., formation water, hydrocarbons from the formation, or modelhydrocarbons prior to characterization, measurements, or experiments.

In one embodiment to ensure the complete saturation of the samples, theselected cores are placed in a pressure chamber with multiple accessports with at least one port being connected to a vacuum source, whileat least another port is connected to the saturation fluid source. Thisair tight pressure vessel is put under vacuum for a few hours to ensurethat all air is removed from the vessel. After air evacuation, aprepared saturation fluid is allowed to fill the pressure vessel. Oncethe pressure vessel is filled with the saturation fluid, the liquidpressure is increased slowly, e.g., to 1000 psig, and allowed tostabilize under pressure for 4 hours. At the end of this stabilizationtime, the pressure in the chamber can be reduced and de-pressurized. Thesamples can be removed and saturated with a fluid, e.g., hydrocarbons,brine, etc.

Characterizing Petrophysical/Geochemistry Properties: The rock samplescollected are tested to gather geochemistry information and conductpetrophysical analyses including but not limited to permeability,surface area, pore volume, porosity, and/or matrix density. The rocksamples can be characterized/analyzed both before and after certainexperiments, e.g., imbibition or cation exchange experiments.

Methods to characterize rock samples to obtain mineral composition,mineral structure, permeability, pore volume, pore structure, and fluidcompatibility include but are not limited to QXRD (quantitative X-raydiffraction), Fourier transform infrared spectroscopy (FTIR), CEC(cation exchange capacity), detailed clay analysis, TOC (total organiccarbon), Rock-Eval™ pyrolysis, SCA (special core analysis), pyrolysisgas chromatography (py-GC/MS), Poro-Perm™ method, Mercury InjectionCapillary Pressure (MICP), water immersion porosimetry, relativepermeability, Klinkenberg permeability, NMR (nuclear magnetic resonanceto measure fluid saturation), thermal gravimetric mass spectrometry(TGMS), and/or microscopy (e.g. light microscopy and scanning electronmicroscopy). In one embodiment, QXRD and FTIR are used to reveal thestructural and crystal chemical variety in the rock samples, e.g.,composition ranges and identification criteria for mica varieties in therock samples.

Methods for geochemistry evaluation/characterizing rocks are describedin: “Specific surface area and pore-size distribution in clays andshales” by Kuila et al., Geophysical Prospecting, 2013, 61, 341-362;“Basic Petroleum Geochemistry for Source Rock Evaluation” by McCathy etal., Oilfield Review Summer 2011:23, no. 2; “Nano-scale Texture andPorosity of Organic Matter and Clay Minerals in Organic-Rich Mudrocks”by Kuila et al., Fuel 135 (2014) 359-373; each of the references areincorporated herein by reference.

In one embodiment, the permeability measurements are carried out on thesamples with a gas permeameter applying Klinkenberg effect correctionsto obtain the liquid permeability. In another embodiment, the rocksamples undergo micro-CT/nano-CT imaging to provide formation fracturecharacteristics. In one embodiment, porosity measurements are carriedout using any of helium porosimetry-mercury immersion (HPMI), mercuryinjection capillary pressure (MICP) and nuclear magnetic resonance(NMR).

The measured rock properties are used in potential fracture fluiddesign. In some embodiments, fracture fluid effects are evaluated bymethods described previously along with two significant methods. Thefirst is that potential fracture fluids are tested on liquid hydrocarbonsaturated core plug samples in a hydrothermal reaction vessel atmoderate temperature and pressure for various lengths of time (FIG. 3).Core plugs will initially undergo standard 2D T1-T2 NMR analysis beforeand after treatment (FIG. 4). A detailed experimental procedure isdescribed in the below:

Plug and fluid characterization prior to NMR analysis Obtain standardend-trims and process for: WIP-RockSat porosity, oil and watersaturation. Obtain SGA-N₂ isotherm and PSD. Obtain NMR spectra on puresaturation fluids NMR Plug Procedure Receive shale plugs at as-receivedcondition: Record the weight for each plug; NMR measurement (T1-T2and/or D-T2) to determine the initial saturation of each plug; Vacuumdry the shale plugs at 80° C. (Temperature and time used for drying aretentative). Upon completion of vacuum drying: Record the weight for eachplug; NMR measurement (T1-T2 and/or D-T2) to determine the saturation ofremaining fluid; Saturate the shale plugs with decane. Vacuum will bepulled on the samples to around 0.3 Torr before pressurizing the decaneto 2000 psig. The decane saturation for shale plugs usually last 4 to 5days and the pressure is kept at 2000 psig. Upon completion of decanesaturation: Record the weight for each plug; NMR measurement (T1-T2and/or D-T2) to determine the porosity at 100% decane saturatedcondition; Calibrate the NMR porosity with core porosity; Submerge thedecane saturated shale plugs in designated solution with moderatepressure. The time used for the imbibition and reaction varies. Uponcompletion: Record the weight for each plug; NMR measurement (T1-T2and/or D-T2) to determine the oil saturation and the solution saturationafter surfactant treatment; Calculate the oil recovery factor; Estimatethe penetration of solution into the pore space during the imbibition;Evacuate the post-treatment shale plugs to remove movable oil. If thisstep is applicable, upon completion: Record the weight for each plug;NMR measurement (T1-T2 and/or D-T2) to determine the residual oilsaturation; Calculate oil recovery factor based on NMR results;Calibrate with oil recovery factor based on mass balance; Vacuum dry theshale plugs at 80° C. (Temperature and time used for drying aretentative). Upon completion: Record the weight for each plug; NMRmeasurement (T1-T2 and/or D-T2) to determine the saturation of remainingfluid; Re-saturate the shale plugs with brine. Same procedure as shownin Step 3. Upon completion: Record the weight for each plug; NMRmeasurement (T1-T2 and/or D-T2) to determine the porosity at 100% brinesaturated condition; Calibrate the NMR porosity with core porosity.

In addition to the above procedures and protocols, surface energyrelated to oil/water wettability and other properties will be conductedwith the technique referred to as inverse gas chromatography surfaceenergy analysis (IGC-SE). Inverse gas chromatography is a physicalcharacterization technique that is used in the analysis of the surfacesof solids. IGC is a sensitive and versatile gas phase technique used tostudy the surface and bulk properties of materials in powder or granularform, where the roles of the stationary (solid) and mobile (gas orvapor) phases are inverted. In IGC, a single gas or vapor (probemolecule) is injected into a column packed with the solid sample underinvestigation. Instead of being a separation and analysis technique, asin normal gas chromatography (GC), IGC is considered a materialscharacterization technique.

Characterizing Injection Fluid (Brine) Properties: Samples of injectionfluid, e.g., formation brine, recycled water, sea water, etc. areanalyzed for properties including alkalinity, salinity, total dissolvedsolids (TDS) properties, e.g., amounts and types of cations andassociated anions.

Characterizing Hydrocarbons Properties: Samples from the variousformations are analyzed for properties and characteristics, e.g.,resins, aromatics, carboxylic acids, etc., including but not limited topolar organic molecules and asphaltene (C10+) contents.

Obtaining Contact Angle/Zeta Potential/Interfacial Tension Measurements:One factor in the determination of the wettability of crude oil/mineralsystems is the electrical or zeta potential of the crude oil/brineinterface and the mineral/brine interface. Mineral here refers to theformation rock. Brine here refers to the fracturing fluid underconsideration. Any of contact angle/zeta potential/interfacial tensiondata measurements can be obtained using methods known in the art.Contact angle and zeta potential can be measured using electrochemicalsensing technology and commercially available instruments. Interfacialtensions can be measured using a spinning drop tensiometer or calculatedfrom phase behavior experiments. Wettability measurements can be carriedout before and after certain experiments, e.g., imbibition or cationexchange experiments.

Data is collected correlating the changes in zeta potential, contactangle, interfacial tension from various rock samples as a function ofvariables including but not limited to temperature, pH/salinity, andcompositions of the fracturing fluid samples. In one embodiment, themeasurements are conducted with a Kruss DSA 100 apparatus equipped withsoftware to capture contact angle and IFT data. The range and accuracyof the contact angle measurement are from 0° to 180° with a resolutionof +/−0.1. The IFT measurements range from 0.01 to 100 mN/m with aresolution of 0.01 mN/m. Digital imaging can also be provided from thisequipment.

In the tests, sample drops of the brine and/or fracturing fluid areinjected onto the test surface of the rock samples. Once the dropletbecame stable, the parameters of the fluids, drop phase and surroundingphase are entered into the DSA 100 software and along with the capturedimage of the droplet, the IFT can be calculated using the Pendant proptechnique. With respect to the contact angle, saturated core plugs areplaced in glass containers filled with the chosen fluid (e.g., a brinesample or a fracturing fluid sample). A drop of a hydrocarbon sample(e.g., mineral oil, crude from the formation, etc.) is placed onto thesubstrate selected to represent the in-situ condition. Once the dropbecame stable, an image of the droplet contact angle is captured by theDSA 100 and the contact angle can be measured. The contact angle can bemeasured using the Young-Laplace method.

In one embodiment, some of the fracturing fluids are selected forfurther tests depending on their performance in the wettability tests,e.g., fluids that would cause a shift in the contact angle of the rocksamples from oil-wet conditions (contact angle greater than 90 degrees)to water-wet condition (contact angle less than 90 degrees).

Conducting Ion Selectivity Test: In one embodiment, the ion selectivityof the various fracturing fluids is evaluated. The ion selectivity testmeasures the voltage drop across a rock sample that is in contact withfracturing fluids of different salinities. The ion selectivity reflectsthe ability of the rock to restrict anions from passing through. Methodsfor measuring ion selectivity are known in the art, e.g., as disclosedin “A Rapid, Rigsite Deployable, Electrochemical Test for Evaluating theMembrane Potential of Shales” by Al-Bazali et al., 2005, SPE AnnualTechnical Conference and Exhibition, 9-12 Oct. 2005, incorporated hereinby reference in its entirety. The electrochemical potential (ECP) datais used to calculate ion selectivity following published works.Correlation is made with other rock property data including, but notlimited to: porosity, permeability, cation exchange capacity (CEC),mineralogy and pore size distribution (FIG. 5).

NMR Test Procedures and Data Processing: The NMR measurements may beperformed with a Tecmag, Apollo LF1 spectrometer at a Larmor frequencyof approximately 2 MHz with a 41-mm probe capable of measuring echospacing to 200 microseconds. The spectrometer can accommodatecylindrical samples up to about 5 cm in length and up to about 4 cm indiameter, having a minimum sample pore volume of 0.2 cm³. NMR systemfrequency, RF coil, and pulse widths are tuned daily. The NMR systemresponse (fluid volume versus amplitude) is verified daily using knownstandards.

The core samples are allowed to equilibrate at system temperature priorto the NMR measurements. The transverse relaxation times (T2) andlongitudinal relaxation times (T1) are determined simultaneously using atwo-dimensional pulse sequence (T1CVX) with a minimum inter-echo spacingof 200 microseconds. T1CVX pulse sequence is repeated a sufficientnumber of times to achieve a reasonably good signal to noise ratio. AllNMR measurements may be conducted at 30° C.

For the collected data from each sample, the echo trains are analyzedthrough a regularized multi-exponential process using Matlog. Thisprocess fits the data and divided the data into relaxation timeincrements. The amplitude value for each increment is calculated. Theamplitude values are converted to porosity using calibration values andthe sample bulk volume.

The T1/T2 ratio provides a robust methodology to identify and quantifythe different constituents occupying the pore space of organic-richunconventional mudstone (shale). In such tight low permeabilitylithology containing liquid hydrocarbon, three main constituents can beidentified based on the T1/T2 relationship including: (1) the volumepercent of water tightly bound to clay minerals and possibly fullyoccupying nm to sub-nm diameter pores and capillaries, plus bitumen(CBWB); (2) relatively light oil in oil wet pore systems (OWP); and (3)the volume of oil and water in water wet porosity (WWP). The defaultT1/T2 cut-off values used for differentiating these component are basedon existing publications and can be adjusted based on sample locationand depth or on other relevant data and information.

Obtaining Disjoining Pressure (DP) Measurements: “Disjoining pressure”refers to the pressure difference between a fluid in the pore space of arock sample and that in a bulk solution at the same depth. In oneembodiment, disjoining pressure measurements are obtained to quantifythe interaction between hydrocarbons and the rock surfaces—as separatedby the fracturing fluids as the electrolytes.

Methods to measure disjoining pressure are known in the art, e.g., asdisclosed in “Measurement of Critical Disjoining Pressure for Dewettingof Solid Surfaces” by Basu et al., Journal of Colloid and InterfaceScience, 181, 443-455 (1996), incorporated herein by reference in itsentirety.

Obtaining Cation Exchange Capacity (CEC) Measurements: “Cation exchangecapacity” (CEC) is the capacity of a material, such as clay or soil, forion exchange of positively charged ions between the material and thesurrounding fluid (water), or the quantity of positively charged ions(cations) that the material can accommodate on its negatively chargedsurface. The crystal structure of rock in a formation allows it to swellin the presence of an aqueous fluid, e.g., the fracturing fluid. Theswell may lead to a change in the rheological properties and/or the rateof penetration.

In one embodiment, certain select fracturing fluids are tested with aplurality of rock samples to determine their impact on the swellingproperties of the rock samples, e.g., the CEC expressed as millionequivalent per 100 g, or more commonly as milli-equivalent (meq) per 100g. CEC can also be expressed in terms of its contribution per unit poreQ_(v). Techniques to measure CEC are known in the art, e.g., wetchemistry such as conductometric titration, multiple salinity andmembrane potential. Conductometric titration tests may include any ofmethylene blue method, ammonium acetate method, benzyl ammonium chloridemethod, malachite green method, or silver-thiourea method.

CEC tests can be carried out with a number of fracturing fluids and witha number of representative rock samples for various time periods, e.g.,from several minutes to several days or weeks, depending at least inpart, the diffusion of the fluid into the samples. In one embodiment,the CEC tests are carried out under different conditions of pressure andtemperature representing the conditions of the formation, as the finalswelling volume depends at least in part on the temperature and pressureof the rock samples.

In one embodiment, in addition to or instead of a CEC test, a linearswell meter (LSM) test is employed to determine and/or represent theswelling characteristics of a rock sample in the presence of the varioustested fracturing fluids. Swelling characteristic methods include thosedescribed in “Shale/Mud Inhibition Defined with Rig-Site Methods” SPEDrilling Engineering, Chenevert et al. (September 1989) incorporatedherein by reference.

Conducting Adsorption/Desorption Simulation Tests: In one embodiment tosimulate the stimulation process, the adsorption/desorption of variousfracturing fluid samples are evaluated over certain defined length oftime and under various conditions to evaluate cation exchange and chargecompensation behaviors in an adsorption/desorption simulation test. Thetest is carried out on a plurality of rock samples, brine samples, andfracturing fluid samples to investigate the impact of different cationsexchanged in the structure of clay minerals or adsorbed to the surfaceof rock-forming minerals on wettability and related oil production fromhydrocarbon bearing rocks.

In the test, the cation exchange processes are coupled with thevariation in the hydrated radius of the ions and depend on theelectrostatic attraction of the water molecules to the ions. The chargesof the ions dictate the radius of the hydrated ions and the thickness ofthe water layer on the surface of the mineral. The forces coupled withthe layer thickness drive the adsorption of hydrocarbons to the rocksurface and related production. The test is to evaluate the changes inthe rock properties as to the capacity to adsorb/desorb organicmolecules of fracturing fluids for a given rock formation, and providingkinetic measurements of rock-fluid interaction.

The adsorption/desorption simulation test is carried out with rocksamples classified according to the International Union of Pure andApplied Chemists (IUPAC), where equivalent pore diameter widths <2 nmare termed micropores, 2-50 nm are mesopores, and those >50 nm arereferred to as macropores. While not being bound to theory, it isbelieved that water present in shale formations occupies micropore andsmaller mesopores by mechanical capillary condensation forces. Owing totheir polarity, water molecules are bound to clay minerals and theirassociated exchange cations by electrostatic hydration and Van der Waalsforces.

The adsorption/desorption simulation tests can be carried out with rocksamples of different sizes and geometries, e.g., core plugs in the formof discs, smaller samples in the form of powder or grains. The tests canbe carried out in batch mode, or in a continuous mode with a packed bedof rock samples. In the batch mode, the dynamic response of solid-fluidsystem can be measured after a step change of conditions, e.g., mixingthe solid materials with a fracturing fluid with known initialconcentration and measuring the composition changes of the fluid as afunction of time. In the continuous flow mode with solid materialspacked in a column with the tested fluid flowing continuously throughthe column, kinetic data is obtained by monitoring the effluent'sresponse to a change of inlet fluid, e.g., a concentration step changeat the inlet and monitoring concentration profile at the outlet of thecolumn as a function of time.

In one embodiment, the adsorption/desorption simulation test is carriedout with reservoir rock samples collected from preserved core or corethat still contains significant crude oil saturation. If a core withnatural oil saturation is not available, plugs from the targetedreservoirs will be first cleaned and then saturated with crude oil for aperiod of time, e.g., from a few hours, a few days, a few weeks, etc. Insome embodiments, the tests are carried out with rock samples that aresaturated with model hydrocarbons representative of certain crude oilclasses (aliphatic, aromatic, resins, asphaltenes), to evaluate theadsorption/desorption processes as a result of cation exchange processesand related changes in wettability

In one embodiment of the test, the rock samples undergo a standard ofcation exchange process, wherein the samples undergo a variety of cationexchange treatment, e.g., with each test employing with a differentbrine comprising multivalent/monovalent cations (such as Mg²⁺, Ca²⁺, Na⁺and K⁺) and mixtures thereof, at different concentrations and differentsaturation time, to evaluate the cation exchange and charge compensationbehavior and its impact on the hydrocarbon recovery of the brine(s) foruse in the fracturing fluid. In another embodiment, the samples undergoa variety of cation exchange treatment with fracturing fluids withadditives. The samples are soaked in the fracturing fluid for a periodof time, e.g., from hours to days, in either batch mode or continuousmode.

The soak time in the test for each experiment with a brine/fracturingfluid can vary from a few hours to a few days, a few weeks, or a fewmonths, simulating the shut-in time for shale reservoirs. Othervariations in experimental parameters include but are not limited tofracturing fluid chemistry (e.g., brine compositions in terms of cationspecies and concentration, additive types and concentration), pH of thebrine/fracturing fluid, pressure, temperature, and times.

In one embodiment of a batch test, the samples are filtered with theliquid being analyzed over time to monitor compositional changes, withthe mass transfer rate inside the core samples being calculated based onthe compositional changes of the liquid samples over time. In anotherembodiment of a continuous test, the rock particles are packed inside acolumn with fracturing fluid continuously flowing down the packed bed atcontrolled rates. The fracturing fluid composition and flow iscontrolled to provide a step change of the inlet composition that willpropagate through the packed bed. The fluid composition exiting thebottom of the packed bed is measured as a function of time. Kinetic datais obtained by analyzing the concentration profile over time at theoutlet as a response to the change in the concentration at the inlet.

In one embodiment after the brine is removed from a rock sample (e.g.,using a centrifuge), the sample is transferred to a dialysis system forelectrical conductivity measurements. In another embodiment of the test,the samples are observed and pictures are taken, along with variousmeasurements obtained over a period of the time, including but notlimited to porosity/pore volume/permeability of the rock samples beforeand after the test, amount of oil released over a period of time (e.g.,sample change in weight of the sample after and before saturation withbrine/fracturing fluid), contact angle tests after exposure to thefracturing fluid, oil spreading potential, etc. The samples can also beprocessed using micro/nano computed tomography (CT) to characterize theminerals reacting to injection brine. X-ray CT scanning of slices acrossthe plan of the saturated samples can be taken to aid the visualizationof fluid imbibition into the rock matrix, to help with theselection/identification of the optimal fracturing fluid for a certainrock type.

In one embodiment, the test is carried out for the same rock sample withdifferent fracturing fluid samples (in series) for different periods oftime, simulating different shut-in periods. This type of test can beuseful for use in simulating fracturing operations and/or findingsolutions with operational issues, e.g., correcting the damages causedby a particular fracturing fluid with the use of a different fracturingfluid.

From the tests, the amount of oil, e.g., recovery efficiency, of thedifferent fracturing fluids tested can be estimated based on therelease/oil production as a function of time and/or properties of therock samples. Based on the recovery efficiency, a number of “best” or“optimal” fracturing fluids can be selected for other tests such as afree imbibition test, or for wettability measurements.

“Forced” Imbibition Test: In one embodiment after theadsorption/desorption simulation tests and optionally after wettabilitymeasurements, imbibition measurements are carried out with certainbrines/fracturing fluids to quantify hydrocarbon release due tofracturing fluid-oil-rock interactions under a variety of conditions,e.g., pressure and temperature, to simulate field performance with highpressure injection (“forced imbibition”). The fluids can be selected forthe imbibition test based on acceptable performance from other tests andmeasurements, e.g., desirable wettability characteristics and/or oilrecovery rates from the adsorption/desorption simulation test.

The tests can be carried out under various conditions, e.g.,low-pressure tests for standard imbibition; high-pressure tests forcounter-current imbibition; and scale up to field performancesimulation. Examples of dynamic imbibition tests include tests at lowpressure (e.g., <1,000 psi) and high pressure (e.g., 3,000 to 5,000psi), providing measurements as how fast the imbibition process takesplace in the pore scale. The tests can be carried out with a variety ofcore samples to simulate field performance using different selectedfracturing fluids.

In the imbibition tests, cylindrical core samples can be used. Thesamples can be of varying lengths (e.g., from 2 to 24 cm) and diameters(e.g., 1 to 5 cm). In one embodiment of the test, multiple samples (fromthe same or different rock formations) are first saturated withdifferent hydrocarbon samples, including model hydrocarbons (e.g.,mineral oils), then tested with the same or different fracturing fluidsfor the wetting phase. In another embodiment, the core samples aretested as is. Some of the cores can be epoxy sealed at one end, somecores are epoxy sealed to leave only one end open to imbibition, somecores can be sealed such that only the lateral surface is open, somecores are sealed such that only the ends are open to imbibition. Some ofthe cores can be split or cut partially or entirely lengthwise, with adifferent rock being inserted to simulate a dominating fracture.

The tests are carried out under pressure, e.g., mounted into a metalcore holder (“imbibition cell”) with applied pressure (e.g., N₂ of atleast 500 psi, and up to 4000 psi) and heat, simulating the pumping offracturing fluid under pressure. The samples are kept under pressure forvarying periods of time to simulate shut-in periods. Selected fracturingfluid is injected into one inlet of the cell, with the effluent (i.e.,oil and fracturing fluid) being collected from the outlet of the cell.Oil production over time is mainly produced by water imbibition from thefracture into the matrix, with the fracture providing a path forexpelled oil to flow to the outlet.

The imbibition tests can be carried out at a constant pressure in oneembodiment, and with step by step increase in pressure in anotherembodiment to evaluate the effect of injection pressure on theimbibition potential. At the end of the test, tracer tests can beconducted to validate how much water is imbibed into the core bycomparing before the water imbibition test. Oil recovery rate can bemeasured and correlated as a function of various factors, including butnot limited to imbibition time, open surface area, core length (in termsof the geometry of the core sample), fracturing fluid concentration,composition, oil properties (e.g., viscosity), viscosity ratio of oilvs. fracturing fluid. FIG. 6 illustrates a schematic diagram of animbibition test setup, according to one embodiment.

Modeling Optimizing Fracturing Fluid Design & Selection: Models forpredicting the recovery of hydrocarbons, selection of fracturingfluid(s) for formation(s) with certain rock characteristics can bedeveloped as related to predicted performance, characteristics,predicted properties with respect to wettability, swellingcharacteristics, etc.

can be developed from the input data collected in the library. New testresults from both laboratory and field tests can be added to the libraryover time. Larger sample size (e.g., fracturing fluids, types of rockformation, number of field tests, number of experiments, etc.) leads toincreased precision for the models. Linear and/or non-linear regressionanalyses can be used to develop models; with various forms of functionsdeveloped including power function, an exponential function, apolynomial function, a linear function, and combinations; andoptimization techniques known in the art including but not limited tosort-and-rank of analogies, multi-variable minimization, and empiricalproxies from experimental design method.

The models can take into account various parameters as input data,including:

a first parameter characterizing the petrophysical/geochemistryproperties of the reservoir rocks (e.g., permeability, surface area,pore volume, porosity, matrix density), a second parametercharacterizing the properties of the hydrocarbons (e.g., polarity,acidity and molecular contents), a third parameter characterizing theproperties of the formation brine (e.g., composition and concentrationof monovalent and/or multivalent cations), an optional fourth parametercharacterizing the properties of the fracturing fluids if additives areadded (e.g., concentration and composition of the additives), anoptional fifth parameter with rock-fluid interactions from the varioustests (e.g., CEC, wettability, ion selectivity, contact angle,disjoining pressure), an optional sixth parameter characterizing thefractures inherent in the rock (e.g., micro/nano-CT imaging), and aseventh parameter correlating the mass transfer and kinetic measurementsfrom the adsorption/desorption simulation and/or imbibition tests (e.g.,diffusivity, flow rate, oil recovery/production, oil recovery % as afunction of time). The seventh parameter with mass transfer andimbibition functions can be obtained from history match of imbibitionrecovery curve(s) from the experiments.

Depending on the desired complexity and available computing resources,the models can be relative (e.g., providing a relative ranking betweenvarious fracturing fluids (in terms of composition/concentration ofbrines/additives), or they can be absolute (e.g., making quantitativeestimates with or without calibration to the external data in terms ofpredicting oil recovery). The simulations can be performed at differenthydraulic fracturing conditions, e.g., pressure, shut-in time, etc.,thus allowing optimizing the hydraulic fracturing procedure.

A plurality of models may be derived for different rock formation types(e.g., different mineral classifications), different brines (e.g.,having different types of salts and/or combinations of salts),fracturing fluids (e.g., having different additives and/or combinationsof additives). In some embodiments, the models can evaluate the effectsof different salt ions (e.g., Na+, K+, Mg+, etc.) on theadsorption/desorption characteristics of the rock samples.

From the models, optimal fracturing fluids can be selected or designedfor a particular rock type or reservoir. The developed models can alsobe used to generate predicted values with respect to performance offracturing fluids in certain rock formations. The predicted values maybe statistically compared with measured values from pilot trials and/orfield trials to provide one or more statistical measurements as to theaccuracy of the models or to fine tune the models. The model parameterscan be optimized to scale up the imbibition test from the core scale topilot scale, and to field tests, with the models being used to forecastthe water imbibition potential.

In one embodiment, mechanistic modeling methods are used to enhance thestatistical methods in addressing key physical mechanisms potentiallyimpacting the recovery process as observed at various scale levels, fromlaboratory tests to field-scale performance results. The modelingefforts include numerical simulation to history match or replication ofthe lab-scale behavior before scaling up to field-scale performanceprediction. This provides key understanding of influencing physics andchemistry involved in the imbibition process for optimizing the designof fracturing fluids and executing field applications for each shaleplay or tight rock formation.

In one embodiment, the developed models are used to select and/or forthe design of a fracturing fluid or fluids to be used for a particularformation, e.g., a newly explored or newly investigated formation. Inanother embodiment, the models can be used to help resolve anoperational issue with an existing, with data from the library beingused to predict and/or correct an operational issue with the selection,design, changing the composition the fluids to be injected for each ofthe hydraulic fracturing stages. In yet another embodiment, the resultsfrom a comprehensive test library together with the models, lead to thetailoring/optimization of fracturing fluid(s) for the shale/tightformation under consideration. This approach significantly saves time &resources compared to the trial-and-error approaches in the prior art.

EXAMPLES

The following examples are intended to be non-limiting.

Example 1. In this screening experiment, a number of wettability testswith various fracturing fluids are carried out with a plurality of rocksamples. Contact angle and/or surface tension (IFT) measurements areconducted with a Kruss DS100 apparatus, equipped with software tocapture contact angle and IFT data. The contact angle can be measuredusing the Young Laplace method. The IFT measurement can be measuredusing Pendant drop techniques. Measurement data is collected for thelibrary, correlating wettability characteristics of the fracturing fluidsamples with the rock samples. A number of fracturing fluid candidatescan be selected for further experiments, CEC and/or the adsorption/test.

Example 2. Based on the screen test results in Example 1, e.g.,wettability tests with fracturing fluids giving the best responses forrock samples, a few fracturing fluid candidates are selected for theadsorption/desorption test. Each rock sample, e.g., a core disk, isfirst saturated with a select hydrocarbon sample for 24 hours. Thesample is then centrifuged for a few minutes and decanted. The rocksample is then saturated with a selected fracturing fluid at reservoirtemperature. The release of oil film from the rock surface can beobserved and recorded. Oil production by water imbibition can also bemonitored and recorded. The produced oil can be qualitatively estimatedat the end of the test.

Example 3. After the adsorption/desorption test, the rock samples inExample 2 are tested to measure the contact angle and spreadingpotential to confirm and/or select the fracturing fluids giving acombination of desirable oil production as well as wettabilitycharacteristics.

Example 4. From the wettability measurements, certain fracturing fluidsare selected for the imbibition tests simulating hydraulic fracturingconditions. The test system includes a high pressure and temperaturecoreholder, allowing tests to run at elevated temperatures up to 400° F.and pressures up to 3000 psi, and for both counter-current andco-current free imbibition, and co-current forced imbibition. This coreholder can hold a core plug with lengths from 3 to 12 inches, and can beeither vertically or horizontally positioned. For some tests, thecoreholder is positioned vertically to study gravity effects. Inaddition, a high resolution CT-scanner (with a resolution of 50 microns)is used to monitor water imbibition from fracture into the matrix andobserve its behavior in the matrix. CT-scanning is also used to studythe fracture network and its effect on water imbibition behavior. FIG. 3is a schematic diagram of an imbibition test setup.

In the counter-current imbibition test, the core is mounted in thecoreholder with an applied pressure simulating the desired pressure forhydraulic fracturing, e.g., 1000 psi. The core holder is heated toreservoir temperature approximately 120° F., and fresh crude oil isinjected to displace the residential oil and mobile water if present.The produced water is collected for water chemistry analysis.Approximately 10 PV of crude oil is injected to re-condition the coreand re-establish the initial water saturation. The core is thensubjected to counter-current free imbibition. The fracturing fluid underevaluation is run through the open end face of the core with the otherend closed. The fluid flows through the end face and both oil andcollected downstream of the cycle loop. The produced oil is measuredversus time. When oil production ceases, the test is switched intoforced imbibition by closing the downstream valve and opening the otherend of the core. The forced fluid injected through the core. The forcedimbibition continued until no oil production is observed.

In the co-current imbibition test, a core sample with oil saturation iscut into two halves and a high permeability sandstone wafer with athickness of ˜0.125 inch is sandwiched to make a new core having afracture in the middle. This core configuration provides increasedsurface areas for testing. The fracturing fluid under evaluation isinjected through the core fracture and oil and water is produced fromthe other end of the core. No forced imbibition was conducted after freeimbibition due to this fracture.

The core can be CT-scanned at the end of imbibition test to obtain theresidual saturation distribution (or remaining oil saturation).

Example 5. Both statistical method and mechanistic method are being usedto analyze the test results obtained from various laboratorymeasurements. Statistical method correlates multiple test measurementsand results to observe key parameters that affect the potential outcomesfor prediction. These include, but not limited to, rock type andcharacteristics, fluid type and compositions, and test conditions orconstraints (temperature, pressure, etc.). Mechanistic modeling usesnumerical methods to simulate rock-fluid interaction and flow behavior.Various models of different scales are used to replicate lab-scaleresults observed prior to predicting field-scale performance. Thesenumerical mechanistic models provide the understanding of the underlyingphysics that affect the observed outcomes from the lab measurements andfrom the statistical method. A combination of the two approaches,statistical and mechanistic, supports the prediction forecasting.

Those of ordinary skill in the art will appreciate that variousmodifications may be made to the embodiments disclosed herein. Forexample, one embodiment of a method for optimizing fracturing fluidcompositions for injection into a subterranean formation includesproviding a plurality of rock samples being representative of a rockmatrix within a subterranean formation containing hydrocarbons forrecovery; providing a plurality of brine samples being representative offormation brines of the subterranean formation; providing a plurality ofhydrocarbon samples being representative of hydrocarbons recoverablefrom the subterranean formation; characterizing the rock samples toobtain one or more rock parameters representing geochemistry propertiesof the rock samples, petrophysical properties of the rock samples, orany combination thereof; characterizing the brine samples to obtain oneor more brine parameters representing alkalinity properties of the brinesamples, salinity properties of the brine samples, total dissolvedsolids (TDS) properties of the brine samples, or any combinationthereof; characterizing the hydrocarbon samples to obtain one or morehydrocarbon parameters representing acidity properties of thehydrocarbon samples, polarity properties of the hydrocarbon samples,molecular characteristics properties of the hydrocarbon samples, or anycombination thereof; synthesizing at least two fracturing fluid samplesbased on the rock parameters, the brine parameters, the hydrocarbonparameters, or any combination thereof; and conducting a test on atleast one rock sample and the at least two fracturing fluid samples toevaluate rock-fluid interactions. The test comprises an interfacialtension test to determine contact angle, zeta potential, wettability,interfacial tension properties, or any combination thereof; an ionselectivity test to determine ion selectivity properties; a cationexchange capacity test to determine cation exchange capacity properties;a disjoining pressure test to determine disjoining pressure properties;an adsorption desorption simulation test to determine cation exchangeand charge compensation properties; a forced imbibition test to evaluatekinetic and mass transfer properties; or any combination thereof. Themethod further includes preparing at least one fracturing fluid forinjection into the subterranean formation based on at least twocriteria, wherein the criteria comprises the rock parameters, the brineparameters, the hydrocarbon parameters, the contact angle properties,the zeta potential properties, the wettability properties, theinterfacial tension properties, the ion selectivity properties, thecation exchange capacity properties, the disjoining pressure properties,the cation exchange and charge compensation properties, the kinetic andmass transfer properties, or any combination thereof.

As an example, one of ordinary skill in the art may implement thismethod using the interfacial tension test only. Alternatively, one ofordinary skill in the art may implement this method using the cationexchange capacity test only. Alternatively, one of ordinary skill in theart may implement this method using a combination of the interfacialtension test and the disjoining pressure test only. Alternatively, oneof ordinary skill in the art may implement this method using acombination of the interfacial tension test, the adsorption desorptionsimulation test, and the forced imbibition test only. Various otheralternatives are also possible.

As an example, one of ordinary skill in the art may implement thismethod using a combination of the rock parameters criteria and the brineparameters criteria only. Alternatively, one of ordinary skill in theart may implement this method using a combination of the zeta potentialproperties criteria and the wettability properties criteria only.Alternatively, one of ordinary skill in the art may implement thismethod using a combination of the wettability properties criteria, theinterfacial tension properties criteria, and the disjoining pressureproperties criteria only. Various other alternatives are also possible.

For the purposes of this specification and appended claims, unlessotherwise indicated, all numbers expressing quantities, percentages orproportions, and other numerical values used in the specification andclaims, are to be understood as being modified in all instances by theterm “about.” Accordingly, unless indicated to the contrary, thenumerical parameters set forth in the following specification andattached claims are approximations that may vary depending upon thedesired properties sought to be obtained by the present invention,inclusive of the stated value and has the meaning including the degreeof error associated with measurement of the particular quantity. Thisterm “about” generally refers to a range of numbers that one of ordinaryskill in the art would consider as a reasonable amount of deviation tothe recited numeric values (i.e., having the equivalent function orresult). For example, this term “about” can be construed as including adeviation of ±10 percent of the given numeric value provided such adeviation does not alter the end function or result of the value.Therefore, a value of about 1% can be construed to be a range from 0.9%to 1.1%.

As used in this specification and the following claims, the terms“comprise” (as well as forms, derivatives, or variations thereof, suchas “comprising” and “comprises”) and “include” (as well as forms,derivatives, or variations thereof, such as “including” and “includes”)are inclusive (i.e., open-ended) and do not exclude additional elementsor steps. For example, the terms “comprises” and/or “comprising,” whenused in this specification, specify the presence of stated features,integers, steps, operations, elements, and/or components, but do notpreclude the presence or addition of one or more other features,integers, steps, operations, elements, components, and/or groupsthereof. Accordingly, these terms are intended to not only cover therecited element(s) or step(s), but may also include other elements orsteps not expressly recited.

While various embodiments are described in terms of “comprising,”“containing,” or “including” various components or steps, thecompositions and methods can also “consist essentially of” or “consistof” the various components and steps. All numbers and ranges disclosedabove may vary by some amount. Whenever a numerical range with a lowerlimit and an upper limit is disclosed, any number and any included rangefalling within the range is specifically disclosed. Also, the terms inthe claims have their plain, ordinary meaning unless otherwiseexplicitly and clearly defined by the patentee. If there is any conflictin the usages of a word or term in this specification and one or morepatent or other documents that may be incorporated herein by reference,the definitions that are consistent with this specification should beadopted.

Furthermore, as used herein, the use of the terms “a” or “an” when usedin conjunction with an element may mean “one,” but it is also consistentwith the meaning of “one or more,” “at least one,” and “one or more thanone.” Thus, it is noted that, as used in this specification and theappended claims, the singular forms “a,” “an,” and “the,” include pluralreferences unless expressly and unequivocally limited to one referent.As used herein, the term “include” and its grammatical variants areintended to be non-limiting, such that recitation of items in a list isnot to the exclusion of other like items that can be substituted oradded to the listed items. As used herein, the use of “may” or “may be”indicates that a modified term is appropriate, capable, or suitable foran indicated capacity, function, or usage, while taking into accountthat in some circumstances the modified term may sometimes not beappropriate, capable, or suitable. Furthermore, unless explicitlydictated by the language, the term “and” may be interpreted as “or” insome instances.

It is understood that when combinations, subsets, groups, etc. ofelements are disclosed (e.g., combinations of components in an item, orcombinations of steps in a method), that while specific reference ofeach of the various individual and collective combinations andpermutations of these elements may not be explicitly disclosed, each isspecifically contemplated and described herein. By way of example, if anitem is described herein as including a component of type A, a componentof type B, a component of type C, or any combination thereof, it isunderstood that this phrase describes all of the various individual andcollective combinations and permutations of these components. Forexample, in some embodiments, the item described by this phrase couldinclude only a component of type A. In some embodiments, the itemdescribed by this phrase could include only a component of type B. Insome embodiments, the item described by this phrase could include only acomponent of type C. In some embodiments, the item described by thisphrase could include a component of type A and a component of type B. Insome embodiments, the item described by this phrase could include acomponent of type A and a component of type C. In some embodiments, theitem described by this phrase could include a component of type B and acomponent of type C. In some embodiments, the item described by thisphrase could include a component of type A, a component of type B, and acomponent of type C. In some embodiments, the item described by thisphrase could include two or more components of type A (e.g., A1 and A2).In some embodiments, the item described by this phrase could include twoor more components of type B (e.g., B1 and B2). In some embodiments, theitem described by this phrase could include two or more components oftype C (e.g., C1 and C2). In some embodiments, the item described bythis phrase could include two or more of a first component (e.g., two ormore components of type A (A1 and A2)), optionally one or more of asecond component (e.g., optionally one or more components of type B),and optionally one or more of a third component (e.g., optionally one ormore components of type C). In some embodiments, the item described bythis phrase could include two or more of a first component (e.g., two ormore components of type B (B1 and B2)), optionally one or more of asecond component (e.g., optionally one or more components of type A),and optionally one or more of a third component (e.g., optionally one ormore components of type C). In some embodiments, the item described bythis phrase could include two or more of a first component (e.g., two ormore components of type C (C1 and C2)), optionally one or more of asecond component (e.g., optionally one or more components of type A),and optionally one or more of a third component (e.g., optionally one ormore components of type B).

Unless defined otherwise, all technical and scientific terms used hereinhave the same meanings as commonly understood by one of skill in the artto which the disclosed invention belongs.

This written description uses examples to disclose the invention,including the best mode, and also to enable any person skilled in theart to make and use the invention. The patentable scope is defined bythe claims, and may include other examples that occur to those skilledin the art. Such other examples are intended to be within the scope ofthe claims if they have structural elements that do not differ from theliteral language of the claims, or if they include equivalent structuralelements with insubstantial differences from the literal languages ofthe claims. All citations referred herein are expressly incorporated byreference.

The invention claimed is:
 1. A method for injecting a fracturing fluidcomposition into a subterranean formation, the method comprising:preparing a fracturing fluid composition for injection into asubterranean formation, wherein the fracture fluid composition isselected based on rock-fluid interactions that are determined from: aninterfacial tension test to determine contact angle properties, zetapotential properties, wettability properties, interfacial tensionproperties, or any combination thereof; an ion selectivity test todetermine ion selectivity properties; a cation exchange capacity test todetermine cation exchange capacity properties; a disjoining pressuretest to determine disjoining pressure properties; an adsorptiondesorption simulation test to determine cation exchange and chargecompensation properties; a forced imbibition test to evaluate kineticand mass transfer properties; or any combination thereof; and injectingthe fracturing fluid composition into the subterranean formation toincrease production of hydrocarbons from the subterranean formation. 2.The method of claim 1, further comprising: providing a plurality of rocksamples being representative of a rock matrix within the subterraneanformation; providing a plurality of brine samples being representativeof formation brines of the subterranean formation; providing a pluralityof hydrocarbon samples being representative of hydrocarbons recoverablefrom the subterranean formation; characterizing the rock samples toobtain one or more rock parameters representing geochemistry propertiesof the rock samples, petrophysical properties of the rock samples, orany combination thereof; characterizing the brine samples to obtain oneor more brine parameters representing alkalinity properties of the brinesamples, salinity properties of the brine samples, total dissolvedsolids (TDS) properties of the brine samples, or any combinationthereof; and characterizing the hydrocarbon samples to obtain one ormore hydrocarbon parameters representing acidity properties of thehydrocarbon samples, polarity properties of the hydrocarbon samples,molecular characteristics properties of the hydrocarbon samples, or anycombination thereof.
 3. The method of claim 2, further comprising:compiling a database comprising the rock parameters, the brineparameters, the hydrocarbon parameters, the contact angle properties,the zeta potential properties, the wettability properties, theinterfacial tension properties, the ion selectivity properties, thecation exchange capacity properties, the disjoining pressure properties,the cation exchange and charge compensation properties, the kinetic andmass transfer properties, or any combination thereof; generating atleast one model representative of the subterranean formation utilizinginformation from the database; and performing mechanistic modeling usingnumerical simulation or experimental design methods to estimatehydrocarbon recovery from the subterranean formation for the fracturingfluid composition being injected into the subterranean formation.
 4. Themethod of claim 3, further comprising: adding to the databasehydrocarbon recovery data obtained from injection of the fracturingfluid composition into the subterranean formation; and updating themodel representative of the subterranean formation based on thehydrocarbon recovery data; and updating the estimate of hydrocarbonrecovery from the subterranean modeling methods.
 5. The method of claim4, wherein updating the estimate of hydrocarbon recovery furthercomprises performing mechanistic modeling, statistical modeling, or anycombination thereof with the updated model.
 6. The method of claim 3,wherein the model is used to identify fracturing fluid compositionshaving an estimated hydrocarbon recovery from the subterranean formationhydrocarbon above a predetermined threshold.
 7. The method of claim 2,further comprising: compiling a model correlating (a) the ionselectivity properties, the cation exchange capacity properties, thedisjoining pressure properties, or any combination thereof with (b) therock parameters, the brine parameters, the hydrocarbon parameters, thecontact angle properties, the zeta potential properties, the wettabilityproperties, the interfacial tension properties, the cation exchange andcharge compensation properties, the kinetic and mass transferproperties, or any combination thereof.
 8. The method of claim 2,further comprising: compiling a model correlating (a) the contact angleproperties, the zeta potential properties, the wettability properties,the interfacial tension properties, or any combination thereof with (b)the rock parameters, the brine parameters, the hydrocarbon parameters,the ion selectivity properties, the cation exchange capacity properties,the disjoining pressure properties, the cation exchange and chargecompensation properties, the kinetic and mass transfer properties, orany combination thereof.
 9. The method of claim 2, further comprising:characterizing fractures in the rock samples by micro-CT imaging,nano-CT imaging, or both; and compiling a model correlating (a) thefractures in the rock samples with (b) the rock parameters, the brineparameters, the hydrocarbon parameters, the contact angle properties,the zeta potential properties, the wettability properties, theinterfacial tension properties, the ion selectivity properties, thecation exchange capacity properties, the disjoining pressure properties,the cation exchange and charge compensation properties, the kinetic andmass transfer properties, or any combination thereof.
 10. The method ofclaim 2, wherein the fracturing fluid composition for injection into thesubterranean formation is synthesized based on the rock parameters, thebrine parameters, the hydrocarbon parameters, or any combinationthereof.
 11. The method of claim 2, wherein the rock parameters comprisepermeability, surface area, pore volume, porosity, matrix density,structural and crystal chemical variety, or any combination thereof. 12.The method of claim 1, wherein one or more of the interfacial tensiontest, ion selectivity test, cation exchange capacity test, disjoiningpressure test, adsorption desorption simulation test, and forcedimbibition test used to determine the rock-fluid interactions areconducted on at least one rock sample representative of a rock matrixwithin the subterranean formation and at least two fracturing fluidsamples.
 13. The method of claim 12, further comprising: saturating theat least one rock sample with at least one hydrocarbon sample prior toconducting the forced imbibition test.
 14. The method of claim 12,wherein: at least one fracturing fluid sample is selected for the forcedimbibition test based on the contact angle properties, the zetapotential properties, the wettability properties, the interfacialtension properties, or any combination thereof.
 15. The method of claim12, wherein: each fracturing fluid sample has a different brinecomposition comprising varying concentrations of multivalent cations,monovalent cations, or any combination thereof; the rock sample issaturated in each fracturing fluid sample for different periods of time;and a hydrocarbon recovery rate is monitored over time to evaluate thecation exchange and charge compensation properties for each of thefracturing fluid samples.
 16. The method of claim 1, wherein thefracturing fluid composition is injected into the subterranean formationin a hydraulic fracturing operation.
 17. The method of claim 1, whereinthe forced imbibition test comprises at least one of a counter-currentimbibition test under pressure of at least 500 psi, a co-currentimbibition test under pressure of at least 500 psi, or any combinationthereof.
 18. The method of claim 1, wherein the fracturing fluidcomposition comprises a fluid loss control additive, a nucleophilicagent, a biocide, a friction reducer, a pH reducing agent, a surfactant,a polymer, or any combination thereof.
 19. The method of claim 1,further comprising verifying compatibility of components in thefracturing fluid composition before injection into the subterraneanformation.
 20. The method of claim 1, further comprising verifyingcompatibility of the fracturing fluid composition with at least oneother fluid that will also be injected into the subterraenan formationbefore injection of the fracturing fluid composition into thesubterranean formation.
 21. The method of claim 1, wherein thefracturing fluid composition includes a surfactant and the compatibilityof the surfactant is verified with at least one other additive of thefracturing fluid composition before injection of the fracturing fluidcomposition into the subterranean formation.
 22. The method of claim 1,wherein the fracturing fluid composition includes a surfactant and thecompatibility of the surfactant is verified with a temperature conditionof the subterranean formation, a salinity of a formation brine of thesubterranean formation, hydrocarbons in the subterranean formation, orany combination thereof before injection of the fracturing fluidcomposition into the subterranean formation.
 23. The method of claim 1,wherein the fracturing fluid composition is injected into thesubterranean formation for re-fracturing stimulation of the subterraneanformation.
 24. The method of claim 1, wherein the subterranean formationis a tight rock formation.
 25. The method of claim 1, wherein thesubterranean formation is a shale formation.
 26. A method for injectinga fracturing fluid composition into a subterranean formation, the methodcomprising: preparing a fracturing fluid composition for injection intoa subterranean formation, wherein the fracture fluid composition isselected based on rock-fluid interactions stored in a database, whereinthe database was generated using: rock parameters representative of arock matrix within the subterranean formation; brine parameters beingrepresentative of formation brines of the subterranean formation;hydrocarbon parameters being representative of hydrocarbons recoverablefrom the subterranean formation; contact angle properties, zetapotential properties, wettability properties, interfacial tensionproperties, or any combination thereof generated from an interfacialtension test; ion selectivity properties generated from an ionselectivity test; cation exchange capacity properties generated from acation exchange capacity test; disjoining pressure properties generatedfrom a disjoining pressure test; cation exchange and charge compensationproperties generated from an adsorption desorption simulation test;kinetic and mass transfer properties generated from a forced imbibitiontest; or any combination thereof; and injecting the fracturing fluidcomposition into the subterranean formation to increase production ofhydrocarbons from the subterranean formation.
 27. The method of claim26, wherein the fracturing fluid composition is injected into thesubterranean formation in a hydraulic fracturing operation.
 28. Themethod of claim 26, wherein the fracturing fluid composition is injectedinto the subterranean formation for re-fracturing stimulation of thesubterranean formation.
 29. The method of claim 26, wherein thesubterranean formation is a tight rock formation.
 30. The method ofclaim 26, wherein the subterranean formation is a shale formation. 31.The method of claim 26, wherein the fracturing fluid compositioncomprises a fluid loss control additive, a nucleophilic agent, abiocide, a friction reducer, a pH reducing agent, a surfactant, apolymer, or any combination thereof.